Composition and method relating to the prevention and remediation of surfactant gel damage

ABSTRACT

Methods for treating a subterranean formation can comprise introducing a treatment fluid comprising dicarboxymethyl glutamic acid (GLDA) or a salt thereof into a subterranean formation. Methods for treating a sandstone formation can comprise introducing a treatment fluid comprising GLDA or a salt thereof into a sandstone formation, the treatment fluid having a pH above about 3.

RELATED APPLICATION

This application is a continuation of U.S. patent application Ser. No.11/499,447, filed Aug. 4, 2006, and published as 2008/0035340 which isincorporated herein by reference in its entirety.

BACKGROUND

The present invention relates generally to treating subterraneanformations and, more particularly, to compositions and methods relatingto the prevention and remediation of surfactant gel damage.

Viscosified treatment fluids may be used in a variety of subterraneantreatments. Such treatments include, but are not limited to, drillingoperations, stimulation treatments, and sand control treatments. As usedherein, the term “treatment,” or “treating,” refers to any subterraneanoperation that uses a fluid in conjunction with a desired functionand/or for a desired purpose. The term “treatment,” or “treating,” doesnot imply any particular action by the fluid.

An example of one such subterranean treatment is a drilling operation,wherein a treatment fluid (e.g., a drilling fluid) passes down throughthe inside of the drill string, exits through the drill bit, and returnsto the drilling rig through the annulus between the drill string andwell bore. The circulating drilling fluid, among other things,lubricates the drill bit, transports drill cuttings to the surface, andbalances the formation pressure exerted on the well bore. Drillingfluids typically require sufficient viscosity to suspend drill cuttings.Viscosified treatment fluids also may be used in other operations totransport and remove formation particulates from the well bore or thenear well bore region. In some instances, these formation particulatesmay be generated during the course of drilling, digging, blasting,dredging, tunneling, and the like in the subterranean formation.

A common production stimulation operation that employs a viscosifiedtreatment fluid is hydraulic fracturing. Hydraulic fracturing operationsgenerally involve pumping a treatment fluid (e.g., a fracturing fluid)into a well bore that penetrates a subterranean formation at asufficient hydraulic pressure to create or enhance one or more cracks,or “fractures,” in the subterranean formation. The fracturing fluid maycomprise particulates, often referred to as “proppant particulates,”that are deposited in the fractures. The proppant particulates function,inter alia, to prevent the fractures from fully closing upon the releaseof hydraulic pressure, forming conductive channels through which fluidsmay flow to the well bore. Once at least one fracture is created and theproppant particulates are substantially in place, the viscosity of thefracturing fluid usually is reduced (i.e., “breaking” the fluid), andthe fracturing fluid may be recovered from the formation. The term“break” and its derivatives, as used herein, refer to a reduction in theviscosity of a fluid, e.g., by the breaking or reversing of thecrosslinks between polymer molecules in the fluid, or breaking chemicalbonds of gelling agent polymers in the fluid. No particular mechanism isimplied by the term.

Another production stimulation operation that employs a viscosifiedtreatment fluid is an acidizing treatment. In acidizing treatments,subterranean formations comprising acid-soluble components, such asthose present in carbonate and sandstone formations, are contacted witha treatment fluid comprising an acid. For example, where hydrochloricacid contacts and reacts with calcium carbonate in a formation, thecalcium carbonate is consumed to produce water, carbon dioxide, andcalcium chloride. In another example, where hydrochloric acid contactsand reacts with dolomite in a formation, the dolomite is consumed toproduce water, carbon dioxide, calcium chloride, and magnesium chloride.After acidization is completed, the water and salts dissolved thereinmay be recovered by producing them to the surface, e.g., “flowing back”the well, leaving a desirable amount of voids (e.g., wormholes) withinthe formation, which enhance the formation's permeability and mayincrease the rate at which hydrocarbons may subsequently be producedfrom the formation.

Viscosified treatment fluids are also utilized in sand controltreatments, such as gravel-packing treatments, wherein a treatmentfluid, which is usually viscosified, suspends particulates (commonlyreferred to as “gravel particulates”) for delivery to a desired area ina well bore, e.g., near unconsolidated or weakly consolidated formationzones, to form a gravel pack to enhance sand control. One common type ofgravel-packing operation involves placing a sand control screen in thewell bore and packing the annulus between the screen and the well borewith the gravel particulates of a specific size designed to prevent thepassage of formation sand. The gravel particulates act, inter alia, toprevent the formation particulates from occluding the screen ormigrating with the produced hydrocarbons, and the screen acts, interalia, to prevent the particulates from entering the production tubing.Once the gravel pack is substantially in place, the viscosity of thetreatment fluid is often reduced to allow it to be recovered. In somesituations, fracturing and gravel-packing treatments are combined into asingle treatment (commonly referred to as “frac pack” operations) toprovide stimulated production and an annular gravel pack to reduceformation sand production.

In a variety of subterranean operations, it also may be desirable todivert treatment fluids in a subterranean formation because, among otherreasons, the treatment fluid may enter portions of a subterraneanformation with high permeability preferentially at the expense ofportions of the subterranean formation with lesser permeability. Forexample, in acid stimulation operations, it may be desired to contactless permeable portions of the subterranean formation with a treatmentfluid containing an acid so as to achieve the desired stimulation.Certain diverting techniques involve the placement of viscosified fluidsin a subterranean formation so as to plug off the high-permeabilityportions of the formation, thereby diverting subsequently injectedfluids to less permeable portions of the formation. In certaintechniques, a treatment fluid is placed adjacent to a certain portion ofa subterranean formation, and the treatment fluid is viscosified so asto form a gel that, inter alia, temporarily plugs the perforations ornatural fractures in that portion of the formation. The term “gel,” asused herein, and its derivatives include semi-solid, jelly-like statesassumed by some colloidal dispersions. When another treatment fluidencounters the gel, it may be diverted to other portions of theformation.

Maintaining sufficient viscosity in treatment fluids may be importantfor a number of reasons. Viscosity is desirable in drilling operationssince treatment fluids with higher viscosity can, among other things,transport solids, such as drill cuttings, more readily. Maintainingsufficient viscosity is important in fracturing treatments forparticulate transport, as well as to create or enhance fracture width.Particulate transport is also important in sand control treatments, suchas gravel packing. Maintaining sufficient viscosity may be important tocontrol and/or reduce leak-off into the formation, improve the abilityto divert another fluid in the formation, and/or reduce pumpingrequirements by reducing friction in the well bore. At the same time,while maintaining sufficient viscosity of a treatment fluid often isdesirable, it also may be desirable to maintain the viscosity of thetreatment fluid in such a way that the viscosity may be reduced at aparticular time, inter alia, for subsequent recovery of the fluid fromthe formation.

To provide the desired viscosity, polymeric gelling agents commonly areadded to the treatment fluids. The term “gelling agent” is definedherein to include any substance that is capable of increasing theviscosity of a fluid, for example, by forming a gel. Examples ofcommonly used polymeric gelling agents include, but are not limited toguar gums and derivatives thereof, cellulose derivatives, biopolymers,and the like. The use of polymeric gelling agents, however, may beproblematic. For instance, these polymeric gelling agents may leave anundesirable gel residue in the subterranean formation after use, whichmay reduce permeability. As a result, costly remedial operations may berequired to clean up the fracture face and proppant pack. Foamedtreatment fluids and emulsion-based treatment fluids have been employedto minimize residual damage, but increased expense and complexity oftenhave resulted.

To combat perceived problems associated with polymeric gelling agents,some surfactants have been used as gelling agents. It is well understoodthat, when mixed with a fluid in a concentration above the criticalmicelle concentration, the molecules (or ions) of surfactants mayassociate to form micelles. The term “micelle” is defined to include anystructure that minimizes the contact between the lyophobic(“solvent-repelling”) portion of a surfactant molecule and the solvent,for example, by aggregating the surfactant molecules into structuressuch as spheres, cylinders, or sheets, wherein the lyophobic portionsare on the interior of the aggregate structure and the lyophilic(“solvent-attracting”) portions are on the exterior of the structure.These micelles may function, among other purposes, to stabilizeemulsions, break emulsions, stabilize a foam, change the wettability ofa surface, solubilize certain materials, and/or reduce surface tension.When used as a gelling agent, the molecules (or ions) of the surfactantsused associate to form micelles of a certain micellar structure (e.g.,rodlike, wormlike, vesicles, etc., which are referred to herein as“viscosifying micelles”) that, under certain conditions (e.g.,concentration, ionic strength of the fluid, etc.) are capable of, interalia, imparting increased viscosity to a particular fluid and/or forminga gel. Certain viscosifying micelles may impart increased viscosity to afluid such that the fluid exhibits viscoelastic behavior (e.g., shearthinning properties) due, at least in part, to the association of thesurfactant molecules contained therein. As used herein, the term“viscoelastic surfactant fluid” refers to fluids that exhibit or arecapable of exhibiting viscoelastic behavior due, at least in part, tothe association of surfactant molecules contained therein to formviscosifying micelles. Moreover, because the viscosifying micelles maybe sensitive to hydrocarbons, the viscosity of these viscoelasticsurfactant fluids may be reduced after introduction into thesubterranean formation without the need for certain types of gelbreakers (e.g., oxidizers). The term “breaker” is defined herein toinclude any substance that is capable of decreasing the viscosity of afluid. This may allow a substantial portion of the viscoelasticsurfactant fluids to be produced back from the formation without theneed for expensive remedial treatments. Despite these advantages,especially those of viscoelastic surfactants relative to polymericgelling agents, experience has shown that viscoelastic surfactants maystill result in surfactant gel damage to subterranean formation.

SUMMARY

The present invention relates generally to treating subterraneanformations and, more particularly, to compositions and methods relatingto the prevention and remediation of surfactant gel damage.

In one embodiment, the present invention provides a method comprisingproviding a treatment fluid comprising a carrier fluid and at least onecomponent selected from the group consisting of a chelating agent and ascale control agent, and introducing the treatment fluid into asubterranean formation that has been treated with a viscoelasticsurfactant fluid.

In another embodiment, the present invention provides a methodcomprising providing a treatment fluid comprising a carrier fluid and atleast one component selected from the group consisting of a chelatingagent and a scale control agent, and introducing the treatment fluidinto a subterranean formation prior to treating the subterraneanformation with a viscoelastic surfactant fluid.

In yet another embodiment, the present invention provides a methodcomprising providing a treatment fluid comprising a carrier fluid; atleast one component selected from the group consisting of a chelatingagent and a scale control agent; at least one component selected fromthe group consisting of an alcohol, a glycol, a pH modifier, ahydrocarbon, a mutual solvent, an oxidizer, a reducer, an enzyme, atransition metal, a combination thereof, and a derivative thereof; andat least one component selected from the group consisting of anonemulsifier, a demulsifier, a combination thereof, and a derivativethereof; and introducing the treatment fluid into a subterraneanformation

In still another embodiment, the present invention provides a treatmentfluid comprising a carrier fluid; at least one component selected fromthe group consisting of a chelating agent and a scale control agent; atleast one component selected from the group consisting of an alcohol, aglycol, a pH modifier, a hydrocarbon, a mutual solvent, an oxidizer, areducer, an enzyme, a transition metal, a combination thereof, and aderivative thereof; and at least one component selected from the groupconsisting of a nonemulsifier, a demulsifier, a combination thereof, anda derivative thereof.

The features and advantages of the present invention will be readilyapparent to those skilled in the art. While numerous changes may be madeby those skilled in the art, such changes are within the spirit of theinvention.

BRIEF DESCRIPTION OF THE DRAWINGS

For a more complete understanding of the present invention and featuresand advantages thereof, reference is now made to the followingdescription, taken in conjunction with the accompanying drawings, inwhich:

FIG. 1 illustrates the permeability regain of an embodiment of atreatment fluid without a chelating agent; and

FIG. 2 illustrates the permeability regain of a treatment fluidcomprising a chelating agent in accordance with a particular embodimentof the present invention.

DESCRIPTION OF PREFERRED EMBODIMENTS

The present invention relates generally to treating subterraneanformations and, more particularly, to compositions and methods relatingto the prevention and remediation of surfactant gel damage.

In some embodiments, the compositions and methods of the presentinvention may be used, among other things, to remediate subterraneanformations that have been exposed to viscoelastic surfactant fluids. Forexample, the compositions of the present invention may be used to treatsubterranean formations after a proppant placement, gravel packingoperation, frac packing operation, or acidizing operation, or afterusing a fluid loss pill or “work over” fluid, to remediate anysurfactant gel damage that might have occurred during the operation. Inother embodiments, the compositions and methods of the present inventionmay be used to prevent or reduce the occurrence of any possiblesurfactant gel damage to subterranean formations during treatment with aviscoelastic surfactant fluid. For example, the compositions of thepresent invention may be used as a prepad fluid prior to the placementof a proppant pack using a viscoelastic surfactant fluid. In otherembodiments, the compositions of the present invention may include aviscoelastic surfactant and be used to place the proppant itself. Thereare many other advantages and objects of this invention that may berealized.

Generally, the treatment fluids of the present invention comprise acarrier fluid and at least one component selected from the groupconsisting of a chelating agent and a scale control agent. Generally,the carrier fluid of the present invention may comprise any aqueous ornon-aqueous fluid. In particular embodiments, the carrier fluid maycomprise freshwater, saltwater (e.g., water containing one or more saltsdissolved therein), brine (e.g., saturated saltwater), seawater, glycol,combinations thereof, or derivatives thereof. In other embodiments, thecarrier fluid may comprise a liquid chelating agent or scale controlagent by itself. Generally, the carrier fluid may be from any source,provided that it does not contain components that might adversely affectthe stability and/or performance of the treatment fluids of the presentinvention.

Any suitable chelating agent or scale control agent may be used inaccordance with the teachings of the present invention. Examples ofsuitable chelating agents include ethylenediaminetetraacetic acid(“EDTA”), nitrilotriacetic acid (“NTA”),hydroxyethylethylenediaminetriacetic acid (“HEDTA”), dicarboxymethylglutamic acid tetrasodium salt (“GLDA”), diethylenetriaminepentaaceticacid (“DTPA”), propylenediaminetetraacetic acid (“PDTA”),ethylenediaminedi(o-hydroxyphenylacetic) acid (“EDDHA”), glucoheptonicacid, gluconic acid, combinations thereof, and derivatives thereof Asused herein, “derivative” refers to any compound that is made from oneof the listed compounds, for example, by replacing one atom in thecompound with another atom or group of atoms, ionizing the compound, orcreating a salt of the compound. “Derivative” also refers to anyunneutralized species of any of the listed compounds. Examples ofsuitable scale control agents include phosphorous compounds,polyaspartic acid, synthetic polymers, polysaccharide polymers,combinations thereof, and derivatives thereof. Examples of suitablephosphorous compounds include amino tri (methylene phosphonic acid),penta sodium salt of aminotri (methylene phosphonic acid), tetra sodiumsalt of aminotri (methylene phosphonic acid),1-hydroxyethylidene-1,1,-diphosphonic acid, hexamethylenediaminetetra(methylene phosphonic acid), diethylenetriamine penta(methylenephosphonic acid), bis (hexamethylene triamine penta(methylene phosphonicacid)), 2-phosphonobutane-1,2,4-tricarboxylic acid, monoethanloaminediphosphonate, etidronic acid, combinations thereof, and derivativesthereof including, but not limited to, salts thereof, such as potassiumsalts of (1-hydroxyethylidene) diphosphonic acid, tetrasodium(1-hydroxyethylidene) biphosphonate, sodium salts of(1-hydroxyethylidene) diphosphonic acid, disodium salts ofhydroxyethylidene 1,1-diphosphonic acid, sodium salts of diethylenetriamine penta (methylene phosphonic acid), sodium salts of bishexamethylene triamine penta (methylene phosphonic acid), sodium saltsof 2-phosphonobutane-1,2,4-tricarboxylic acid, and tetrasodiumetidronate. Examples of suitable commercially available phosphorouscompounds include phosphonates sold as part of the Dequest productfamily available from Solutia, Inc. of St. Louis, Mo. Examples ofsuitable synthetic polymers include homopolymers of maleic acid,polymers of modified polyacrylic acid, and sulphonated polyacrylic acidcopolymers. Examples of commercially available synthetic polymerssuitable for use in accordance with the teachings of the presentinvention include polymers sold as part of the Dequest product familyavailable from Solutia, Inc. of St. Louis, Mo. Examples of suitablepolysaccharide polymers include carboxymethyl inulin and salts thereof.In particular embodiments, the chelating agent and/or scale controlagent comprises from about 5% to about 60%, by weight, of the treatmentfluid. In some particular embodiments, the chelating agent and/or scalecontrol agent may be present in an amount from about 1 to about 100pounds per gallon of the treatment fluid.

In particular embodiments, the treatment fluids of the present inventionmay also include one or more alcohols, glycols, pH modifiers,hydrocarbons, mutual solvents, oxidizers, reducers, enzymes (such asthose described in U.S. patent application Ser. No. 10/041,528, nowissued as U.S. Pat. No. 7,052,901) transition metals (such as thosedescribed in U.S. patent application Ser. Nos. 11/145,630 and11/225,536, now respectively issued as U.S. Pat. Nos. 7,595,284 and7,261,160 and U.S. patent application Ser. No. 11/225,537, now availableas U.S. patent application publication 2007/0060482), combinationsthereof, or derivatives thereof. In such treatment fluids, the alcohols,pH modifiers, hydrocarbons, mutual solvents, oxidizers, reducers,enzymes, and/or transition metals may help break some of the surfactantgels. Examples of suitable alcohols, pH modifiers, hydrocarbons,oxidizers, and/or transition metals include, but are not limited to,iron compounds, zinc compounds, tin compounds, chromium compounds,thioglycolic acid (or salts thereof), erythorbic acid (or saltsthereof), stannous chloride, sodium persulfate, potassium persulfate,ammonium persulfate, potassium permanganate, sodium permanganate, sodiumperiodate, potassium periodate, sodium bromate,ethyleneglycolmonobutylether, propyleneglycolmonobutylether, sodiumhydroxide, potassium hydroxide, sodium bicarbonate, potassium carbonate,hydrochloric acid, acetic acid, hydrofluoric acid, formic acid,isopropyl alcohol, butanol, and ethanol. In particular embodiments, thetreatment fluids of the present invention may also include organicacids, such as acetic acid, citric acid, lactic acid, combinationsthereof, and derivatives thereof.

In particular embodiments, the treatment fluids of the present inventionmay also include one or more nonemulsifiers, demulsifiers, combinationsthereof, or derivatives thereof. In such treatment fluids, thenonemulsifiers or demulsifiers may help remediate emulsion damage causedby surfactant gel/oil interactions. Examples of suitable non-emulsifiersand/or demulsifiers include, but are not limited to, LOSURF™ 259surfactant, LOSURF™ 300 surfactant, LOSURF™ 357 surfactant, LOSURF™ 400surfactant, LOSURF™ 2000M surfactant, LOSURF™ 2000S surfactant, andNEA-96M™ surfactant, each of which is commercially available fromHalliburton Energy Services, Inc. of Duncan, Okla.

The treatment fluids of the present invention may also include aviscoelastic surfactant. Generally, any suitable surfactant that iscapable of imparting viscoelastic properties to an aqueous fluid may beused in accordance with the teachings of the present invention. Thesesurfactants may be cationic, anionic, nonionic, zwitterionic oramphoteric in nature, and comprise any number of different compounds,including methyl ester sulfonates (such as those described in U.S.patent application Ser. Nos. 11/058,660, 11/058,475, and 11/058,612,respectively issued as U.S. Pat. Nos. 7,299,874, 7,159,659, and7,303,019, and U.S. patent application Ser. No. 11/058,611, nowavailable as U.S. patent application publication 2006/0183646),betaines, modified betaines, sulfosuccinates, taurates, amine oxides,ethoxylated fatty amines, quaternary ammonium compounds, derivativesthereof, and combinations thereof. When present in the treatment fluidsof the present invention, the surfactant is generally present in anamount sufficient to provide the desired viscosity (e.g., sufficientviscosity to divert flow, reduce fluid loss, suspend particulates, etc.)through the formation of viscosifying micelles. In particularembodiments, the surfactant generally comprises from about 0.5% to about10%, by volume, of the treatment fluid. In particular embodiments, thesurfactant comprises from about 1% to about 5%, by volume, of thetreatment fluid.

When including a surfactant, the treatment fluids of the presentinvention may also comprise one or more cosurfactants to, among otherthings, facilitate the formation of and/or stabilize a foam, facilitatethe formation of micelles (e.g., viscosifying micelles), increase salttolerability, and/or stabilize the treatment fluid. The cosurfactant maycomprise any surfactant suitable for use in subterranean environmentsthat does not adversely affect the treatment fluid. Examples ofcosurfactants suitable for use in the present invention include, but arenot limited to, linear C₁₀-C₁₄ alkyl benzene sulfonates, branchedC₁₀-C₁₄ alkyl benzene sulfonates, tallow alkyl sulfonates, coconut alkylglyceryl ether sulfonates, sulfated condensation products of mixedC₁₀-C₁₈ tallow alcohols with about 1 to about 14 moles of ethyleneoxide, and mixtures of higher fatty acids containing about 10 to about18 carbon atoms. In particular embodiments, the cosurfactant may bepresent in an amount in the range of from about 0.05% to about 5% byvolume of the treatment fluid. In particular embodiments, thecosurfactant may be present in an amount in the range of from about0.25% to about 0.5% by volume of the treatment fluid. The type andamount of cosurfactant suitable for a particular application of thepresent invention may depend upon a variety of factors, such as the typeof surfactant present in the treatment fluid, the composition of thetreatment fluid, the temperature of the treatment fluid, and the like. Aperson of ordinary skill, with the benefit of this disclosure, willrecognize when to include a cosurfactant in a particular application ofthe present invention, as well as the appropriate type and amount ofcosurfactant to include.

The treatment fluids of the present invention may optionally compriseone or more salts to modify the rheological properties (e.g., viscosity)of the treatment fluids. These salts may be organic or inorganic.Examples of suitable organic salts include, but are not limited to,aromatic sulfonates and carboxylates (such as p-toluene sulfonate andnapthalene sulfonate), hydroxynapthalene carboxylates, salicylate,phthalate, chlorobenzoic acid, phthalic acid, 5-hydroxy-1-naphthoicacid, 6-hydroxy-1-naphthoic acid, 7-hydroxy-1-naphthoic acid,1-hydroxy-2-naphthoic acid, 3-hydroxy-2-naphthoic acid,5-hydroxy-2-naphthoic acid, 7-hydroxy-2-naphthoic acid,1,3-dihydroxy-2-naphthoic acid, 3,4-dichlorobenzoate, trimethylammoniumhydrochloride and tetramethylammonium chloride. Examples of suitableinorganic salts include water-soluble potassium, sodium, and ammoniumsalts (such as potassium chloride and ammonium chloride), calciumchloride, calcium bromide, magnesium chloride, and zinc halide salts.Examples of viscoelastic surfactant fluids comprising salts suitable foruse in the present invention are described in U.S. patent applicationSer. No. 10/800,478, now available as U.S. patent applicationpublication 2004/0176478, the relevant disclosure of which isincorporated herein by reference. Any combination of the salts listedabove also may be included in the treatment fluids of the presentinvention. Where included, the one or more salts may be present in anamount in the range of about 0.1% to about 75% by weight of thetreatment fluid. In particular embodiments, the one or more salts may bepresent in an amount in the range of about 0.1% to about 10% by weightof the treatment fluid. The type and amount of salts suitable in aparticular application of the present invention may depend upon avariety of factors, such as the type of surfactant present in thetreatment fluid, the composition of the treatment fluid, the temperatureof the treatment fluid, and the like. A person of ordinary skill, withthe benefit of this disclosure, will recognize when to include a salt ina particular application of the present invention, as well as theappropriate type and amount of salt to include.

The treatment fluids of the present invention may also include one ormore well-known additives, such as gel stabilizers, fluid loss controladditives, particulates, acids, corrosion inhibitors, catalysts, claystabilizers, biocides, friction reducers, additional surfactants,solubilizers, pH adjusting agents, bridging agents, dispersants,flocculants, foamers, gases, defoamers, H₂S scavengers, CO₂ scavengers,oxygen scavengers, scale inhibitors, lubricants, viscosifiers, weightingagents, and the like. Those of ordinary skill in the art, with thebenefit of this disclosure, will be able to determine the appropriatetype and amount of such additives for a particular application. Forexample, in some embodiments, it may be desired to foam a treatmentfluid of the present invention using a gas, such as air, nitrogen, orcarbon dioxide.

Generally, the treatment fluids of the present invention may have any pHthat does not adversely affect the subterranean formation into which thefluid is to be introduced and/or the various components of the fluid.For example, in particular embodiments, the treatment fluids of thepresent invention may have a pH above about 3. The treatment fluids ofthe present invention may also have a range of densities, depending,inter alia, on the composition of the fluid and whether or not the fluidis foamed. For example, in particular embodiments, the treatment fluidsmay have a density below about 10 lb/gal.

In some embodiments, the methods of the present invention compriseproviding a treatment fluid comprising a carrier fluid and at least onecomponent selected from the group consisting of a chelating agent and ascale control agent, and introducing the treatment fluid into asubterranean formation. In particular embodiments, the treatment fluidsalso comprise at least one component selected from the group consistingof an alcohol, a glycol, a pH modifier, a hydrocarbon, a mutual solvent,an oxidizer, a reducer, an enzyme, a transition metal, a combinationthereof, and a derivative thereof; and at least one component selectedfrom the group consisting of a nonemulsifier, a demulsifier, acombination thereof, and a derivative thereof. In particular embodimentsof the present invention, the treatment fluids may be used to remediatea subterranean formation that has been previously treated with aviscoelastic surfactant fluid, such as a fracturing fluid, gravelpacking fluid, frac packing fluid, acidizing fluid, fluid loss pill, or“work over fluid.” In such embodiments, the treatment fluids of thepresent invention may help to remediate surfactant gel damage leftbehind by the viscoelastic surfactant fluid.

In other embodiments, the treatment fluids of the present invention maybe used to prevent or reduce the occurrence of surfactant gel damage. Insuch embodiments, the treatment fluids may be utilized as prepad fluids(e.g., fluids comprising neither a crosslinker nor proppant) or padfluids (e.g., a crosslinked fluid comprising no proppant) prior to theplacement of a proppant pack or gravel pack. The treatment fluids of thepresent invention may also be utilized in acidizing, matrix acidizing,fracture acidizing, hydraulic fracturing, gravel packing, and fracpacking treatments, as well as in fluid loss pills and “work overfluids.” In other embodiments, the treatment fluids of the presentinvention may be used to place a proppant pack or gravel pack. In suchembodiments, the treatment typically also comprise a viscoelasticsurfactant. The inclusion of the chelating agent or scale control agentmay help to prevent or reduce the amount of surfactant gel damage causedby the viscoelastic surfactant. In particular embodiments, the treatmentfluids of the present invention may be introduced into a subterraneanformation as a foamed, non-foamed, or emulsion-based treatment fluid.

To facilitate a better understanding of the present invention, thefollowing examples of certain aspects of some embodiments are given. Inno way should the following examples be read to limit, or define, theentire scope of the invention.

EXAMPLE

Two treatment fluids were prepared each comprising 50 gal/Mgal of anapproximately 30% solution of oleamidopropyl betaine, 5 gal/Mgal of anapproximately 75% solution of oleic acid, and approximately 15 gal/Mgalof an approximately 25% solution of NaOH having a pH from about 11.5 toabout 12.5 in approximately 7% KCl. Approximately 0.5 g/200 ml(approximately 21 lb/Mgal) of EDTA was added to one of the samples. Thepermeability regain of the two samples was then tested in Bereasandstone at a temperature of 150° F. and a flow rate of 2 ml/min. Theresults of these tests are shown in FIGS. 1 and 2.

FIG. 1 illustrates the regain permeability of the sample without theEDTA. With a core length of 4.464 cm and a core diameter of 2.528 cm,the non-EDTA sample exhibited a regain of approximately 26%.

FIG. 2 illustrates the regain permeability of the sample containing theEDTA. With a core length of 4.202 cm and a core diameter of 2.518 cm,the EDTA sample exhibited a regain of approximately 91%.

Therefore, the present invention is well adapted to attain the ends andadvantages mentioned as well as those that are inherent therein. Theparticular embodiments disclosed above are illustrative only, as thepresent invention may be modified and practiced in different butequivalent manners apparent to those skilled in the art having thebenefit of the teachings herein. Furthermore, no limitations areintended to the details of construction or design herein shown, otherthan as described in the claims below. It is therefore evident that theparticular illustrative embodiments disclosed above may be altered ormodified and all such variations are considered within the scope andspirit of the present invention. In particular, every range of values(of the form, “from about a to about b,” or, equivalently, “fromapproximately a to b,” or, equivalently, “from approximately a-b”)disclosed herein is to be understood as referring to the power set (theset of all subsets) of the respective range of values, and set forthevery range encompassed within the broader range of values. Also, theterms in the claims have their plain, ordinary meaning unless otherwiseexplicitly and clearly defined by the patentee.

What is claimed is:
 1. A method comprising: providing a portion of asubterranean formation that comprises surfactant gel damage residue froma previous treatment, the portion of the subterranean formation having afirst permeability; placing a treatment fluid in the portion of thesubterranean formation, the treatment fluid comprising a nonemulsifierand dicarboxymethyl glutamic acid (GLDA) or a salt thereof; and,interacting the GLDA or a salt thereof with the surfactant gel damageresidue so as to increase the permeability of the subterranean formationto a second permeability, the second permeability being greater than thefirst permeability and showing a permeability regain of greater than26%.
 2. The method of claim 1 wherein the GLDA or salt thereof comprisesbetween about 5% to about 60% of the treatment fluid by weight.
 3. Themethod of claim 1 wherein the treatment fluid has a pH of above about 3.4. The method of claim 1, wherein the treatment fluid further comprisessurfactant, a corrosion inhibitor, a mutual solvent, or any combinationthereof.
 5. The method of claim 1, wherein the treatment fluid furthercomprises surfactant, a corrosion inhibitor, and a mutual solvent. 6.The method of claim 5, wherein the surfactant comprises between about0.5% to about 10% by volume of the treatment fluid.
 7. The method ofclaim 5, wherein the surfactant comprises between about 0.5% to about10% by volume of the treatment fluid and the GLDA or salt thereofcomprises between about 5% to about 60% of the treatment fluid byweight.
 8. The method of claim 1, wherein the subterranean formationcomprises a sandstone formation.
 9. The method of claim 1, wherein thepermeability regain is greater than 50%.
 10. A method comprising:providing a portion of a sandstone subterranean formation that comprisessurfactant gel damage residue from a previous treatment, the portion ofthe subterranean formation having a first permeability; placing atreatment fluid in the portion of the sandstone subterranean formation,the treatment fluid comprising a nonemulsifier and dicarboxymethylglutamic acid (GLDA) or a salt thereof; and, interacting the GLDA or asalt thereof with the surfactant gel damage residue so as to increasethe permeability of the sandstone subterranean formation to a secondpermeability, the second permeability being greater than the firstpermeability and showing a permeability regain of greater than 26%. 11.The method of claim 10 wherein the GLDA or salt thereof comprisesbetween about 5% to about 60% of the treatment fluid by weight.
 12. Themethod of claim 10 wherein the treatment fluid has a pH of above about3.
 13. The method of claim 10, wherein the treatment fluid furthercomprises surfactant, a corrosion inhibitor, a mutual solvent, or anycombination thereof.
 14. The method of claim 10, wherein the treatmentfluid further comprises surfactant, a corrosion inhibitor, and a mutualsolvent.
 15. The method of claim 14, wherein the surfactant comprisesbetween about 0.5% to about 10% by volume of the treatment fluid. 16.The method of claim 14, wherein the surfactant comprises between about0.5% to about 10% by volume of the treatment fluid and the GLDA or saltthereof comprises between about 5% to about 60% of the treatment fluidby weight.
 17. The method of claim 10, wherein the permeability regainis greater than 50%.
 18. A method comprising: providing a portion of asandstone subterranean formation that comprises surfactant gel damageresidue from a previous treatment, the portion of the subterraneanformation having a first permeability; placing a treatment fluid havinga pH of above about 3 into the portion of the sandstone subterraneanformation, the treatment fluid comprising: a nonemulsifier,dicarboxymethyl glutamic acid (GLDA) or a salt thereof in an amountbetween about 5% to about 60% by weight of the treatment fluid, and, asurfactant in an amount between about 0.5% to about 10% by volume of thetreatment fluid, a corrosion inhibitor, and, a mutual solvent;interacting the GLDA or a salt thereof with the surfactant gel damageresidue so as to increase the permeability of the sandstone subterraneanformation to a second permeability, the second permeability beinggreater than the first permeability and showing a permeability regain ofgreater than 26%.
 19. The method of claim 18, wherein the treatmentfluid further comprises surfactant, a corrosion inhibitor, and a mutualsolvent and wherein the surfactant comprises between about 1% to about5% by volume of the treatment fluid and the GLDA or salt thereofcomprises between about 5% to about 60% of the treatment fluid byweight.
 20. The method of claim 18, wherein the permeability regain isgreater than 50%.